The present invention relates generally to marine riser systems and, in an embodiment described herein, more particularly provides an offshore universal riser system.
Risers are used in offshore drilling applications to provide a means of returning the drilling fluid and any additional solids and/or fluids from a borehole back to surface. Riser sections are sturdily built as they have to withstand significant loads imposed by weights they have to carry and environmental loads they have to withstand when in operation. As such, they have an inherent internal pressure capacity.
However, this capacity is not currently exploited to the maximum extent possible. Many riser systems have been proposed to vary the density of fluid in the riser but none have provided a universally applicable and easily deliverable system for varying types of drilling modes. They typically require some specific modification of the main components of a floating drilling installation, with the result that they are custom solutions with a narrow range of application due to costs and design limitations. For example, different drilling systems are required for different drilling modes such as managed pressure drilling, dual density or dual gradient drilling, partial riser level drilling, and underbalanced drilling.
An example of the most common current practice is illustrated by FIG. 1, which is proposed in U.S. Pat. No. 4,626,135. To compensate for movement of a floating drilling installation, a slip joint SJ (telescopic joint) is used at an upper end of a riser system. This slip joint consists of an inner barrel IB and an outer barrel OB that move relative to each other, thus allowing the floating structure S to move without breaking the riser R between the fixed point wellhead W and the moving point diverter D (which is where drilling fluid is returned from the top of the riser R).
Also depicted in FIG. 1 are a rig structure S, rig floor F, rotary table RT, choke manifold CM, separator MB, shale shaker SS, mud pit MP, choke line CL, kill line KL, booster line BL and rigid flowline RF. These elements are conventional, well known to those skilled in the art and are not described further.
A ball joint BJ (also known as a flex-joint) provides for some angular displacement of the riser R from vertical. The conventional method interprets any pressure in the riser R due to flow of pressurized fluids from wellhead W as an uncontrolled event (kick) that is controlled by closing the BOP (blowout preventer) either by rams around the tubulars therein, or by blind rams if no tubulars are present, or by shear rams capable of cutting the tubulars.
It is possible for the kick to enter the riser R, and then it is controlled by closing the diverter D (with or without tubulars present) and diverting the undesired flow through diverter lines DL. In the '135 patent the concept of an annular blow out preventer used as a gas handler to divert the flow of gas from a well control incident is described. This allows diversion of gas in the riser R by closing around the tubulars therein, but not when drilling, i.e., rotating the tubular.
In FIG. 1, seals between the outer barrel OB and inner barrel IB are subjected to much movement due to wave motion, and this causes a limitation in the pressure sealing capacity available for the riser R. In fact, the American Petroleum Institute (API) has established pressure ratings for such seals in its specification 16F, which calls for testing to 200 psi (pounds per square inch). In practice, the common upper limit for most designs is 500 psi.
There are some modifications that can be made to the slip joint SJ, an example of which is described in U.S. Patent Application No. US2003/0111799A1, to produce a working rating to 750 psi. In practice, the limitation on the slip joint SJ seals has also led to an accepted standard in the industry of the diverter D, ball joint BJ (also sometimes replaced by a unit known as a flex-joint) and other parts of the system (such as valves on the diverter line DL) having a typical industry-wide rating of 500 psi working pressure.
The outer barrel OB of the slip joint SJ (telescopic joint) also acts as an attachment point for a tension system that serves to keep the riser R in tension to prevent it from buckling. This means that a leak in the slip joint SJ seals involves significant downtime in having to lift the entire riser R from the subsea BOP (blowout preventer) stack in order to service the slip joint SJ. In practice this has meant that no floating drilling installation service provider or operating company has been willing to take the risk to continuously operate with any pressure in the riser R for the conventional system (also depicted in FIG. 3a).
U.S. Patent Application No. 2005/0061546 and U.S. Pat. No. 6,913,092 have addressed this problem by proposing the locking closed of the slip joint SJ, which means locking the inner barrel IB to the outer barrel OB, thus eliminating movement across the slip joint seal. The riser R is then effectively disconnected from the ball joint BJ and diverter D as shown in FIG. 2.
The riser R is closed by the addition of a rotating blowout preventer 70 on top of the locked closed slip joint SJ. This effectively decouples the riser R from any fixed point below the rotary table RT.
Also depicted in FIG. 2 are vertical beams B, adapter or crossover 22, rotatable tubular 24 (such as drill pipe) and T-connectors 26. These elements are conventional and are not described further here.
This method has been used and allowed operations with a limit of 500 psi internal riser pressure, with the weak point still being the slip joint seals. However, decoupling the riser R from the fixed rig floor F means that it is only held by the tensioner system T1 and T2.
This means that the top of the riser R is no longer self centralizing. This causes the top of an RCD 80 (rotating control device) of the blowout preventer 10 to be off center as a result of ocean currents, wind or other movement of the floating structure. This introduces significant wear on the sealing element(s) of the RCD 80, which is detrimental to the pressure integrity of the riser system.
Also, the riser system of FIG. 2 introduces a significant safety hazard, since substantial amounts of easily damaged hydraulic hoses used in the operation of the RCD 80, as well as pressurized hose(s) 62 and safety conduit 64, are introduced in the vicinity of riser tensioner wires depicted as extending upwardly from the slip joint SJ to sheaves at the bottom of the tensioners T1, T2. These wires are under substantial loads (on the order of 50 to 100 tons each) and can easily cut through softer rubber goods (such as hoses). The '092 patent suggests the use of steel pipes, but this is extremely difficult to achieve in practice.
Furthermore, the installation and operation requires personnel to perform tasks around the RCD 80, a hazardous area with the relative movement between the floating structure S to the top of the riser R. All of the equipment does not fit through the rotary table RT and diverter housing D, thus making installation complex and hazardous. As a result, use of the system of FIG. 2 has been limited to operations in benign sea areas with little current, wave motion, and wind loads.
A summary of the evolution for the art for drilling with pressure in the riser is shown in FIGS. 3a to 3c. FIG. 3a shows the conventional floating drilling installation set-up. This consists typically of an 18¾ inch subsea BOP stack, with a LMRP (Lower Marine Riser Package) added to allow disconnection and prevent loss of fluids from the riser, a 21 inch marine riser, and a top configuration identical in principle to the '135 patent discussed above. This is the configuration used by a large majority of today's floating drilling installations.
In order to reduce costs, the industry moved towards the idea of using a SBOP (surface blowout preventer) with a floating drilling installation (for example, U.S. Pat. No. 6,273,193 as illustrated in FIG. 4), where the 21 inch riser is replaced with a smaller high pressure riser capped with a SBOP package similar to a non-floating drilling installation set-up as illustrated in FIG. 3b. This design evolved to dispensing completely with the subsea BOP, thus removing the need for choke, kill, and other lines from the sea floor back to the floating drilling installation and many wells were drilled like this in benign ocean areas.
FIG. 4 depicts a riser 74, slip joint 78, collar 102, couplings 92, hydraulic tensioners 68, inner riser 66, load bearing ring 98, load shim 86, drill pipe 72, surface BOP 94, line 76, collar 106 and rotating control head 96. Since these elements are known in the art, they are not described further here.
In attempting to take the concept of a SBOP and high pressure riser further into more environmentally harsh areas, a subsea component for disconnection (known as an environmental safeguard ESG system) and securing the well in case of emergency was re-introduced, but not as a full subsea BOP. This is shown in FIG. 3c with another evolution of running the SBOP below the water line and tensioners above to provide for heave on floating drilling installations with limited clearance. The method of U.S. Pat. No. 6,913,092 is shown in FIG. 3d for comparison.
In trying to plan for substantially higher pressures as experienced in underbalanced drilling where the formation being drilled is allowed to flow with the drilling fluid to surface, the industry has favored designs utilizing an inner riser run within the typical 21 inch marine riser as described in U.S. Patent Application 2006/0021755 A1. This requires a SBOP as shown in FIG. 3e. 
Drawbacks of the systems and methods described above include that they require substantial modification of the floating drilling installation to enable the use of SBOP (surface blowout preventers) and the majority are limited to benign sea and weather conditions. Thus, they are not widely implemented since, for example, they require the floating drilling installation to undergo modifications in a shipyard.
Methods and systems as shown in U.S. Pat. Nos. 6,230,824 and 6,138,774 attempt to dispense totally with the marine riser. Methods and systems described in U.S. Pat. Nos. 6,450,262, 6,470,975, and U.S. Patent Application 2006/0102387A1 envision setting an RCD device on top of the subsea BOP to divert pressure from the marine riser, as does U.S. Pat. No. 7,080,685 B2. All of these patents are not widely applied as they involve substantial modifications and additions to existing equipment to be successfully applied.
FIG. 5 depicts the system described in U.S. Pat. No. 6,470,975. Illustrated in FIG. 5 are pipe P, bearing assembly 28, riser R, choke line CL, kill line KL, BOP stack BOPS, annular BOP's BP, ram BOP's RBP, wellhead W and borehole B. Since these elements are known in the art, further description is not provided here.
A problem with the foregoing systems that utilize a high pressure riser or a riserless setup is that one of the primary means of delivering additional fluids to the seafloor, namely the booster line BL that is a typical part of the conventional system as depicted in FIG. 3a, is removed. The booster line BL is also indicated in FIGS. 1 and 2. So, the systems shown in FIGS. 3b and 3c, while providing some advantages, take away one of the primary means of delivering fluid into the riser. Even when the typical booster line BL is provided, it is tied in to the base of the riser, which means that the delivery point is fixed.
There is also an evolution in the industry to move from conventional drilling to closed system drilling. These types of closed systems are described in U.S. Pat. Nos. 6,904,981 and 7,044,237, and require the closure and (by consequence) the trapping of pressure inside the marine riser in floating drilling installations. Also, the introduction of a method and system to allow continuous circulation as described in U.S. Pat. No. 6,739,397 allows a drilling circulation system to be operated at constant pressure as the pumps do not have to be switched off when making or breaking a tubular connection. This allows the possibility of drilling with a constant pressure downhole, which can be controlled by a pressurized closed drilling system. The industry calls this Managed Pressure Drilling.
With the conventional method of FIG. 3a, no continuous pressure can be kept in the riser. In FIG. 6a, fluid flow in the riser system of FIG. 3a is schematically depicted. Note that the riser system is open to the atmosphere at its upper end. Thus, the riser cannot be pressurized, other than due to hydrostatic pressure of the fluid therein. Since the fluid (mud, during drilling) in the riser typically has a density equal to or only somewhat greater than that of the fluid external to the riser (seawater), this means that the riser does not need to withstand significant internal pressure.
With the method of U.S. Pat. No. 6,913,092 (as depicted in FIG. 3d), the pressure envelope has been taken to 500 psi, however, with the substantial addition of hazards and many drawbacks. It is possible to increase the envelope by the methods shown in FIGS. 3b, 3c and 3e. However, the addition of a SBOP (surface BOP) to a floating drilling installation is not a normal design consideration and involves substantial modification, usually involving a shipyard with the consequence of operational downtime as well as substantial costs involved, as already mentioned above.
The systems mentioned earlier in U.S. Pat. Nos. 6,904,981 and 7,044,237 discuss closing the choke on a pressurized drilling system, and using manipulation of the choke to control the backpressure of the system, in order to control the pressure at the bottom of the well. This method works in principle, but in field applications of these systems, when drilling in a closed system, the manipulation of the choke can cause pressure spikes that are detrimental to the purpose of these inventions, i.e., precise control of the bottom hole pressure.
Also, a peculiarity of a floating drilling installation is, that when a connection is made, the top of the pipe is held stationary in the rotary table (RT in FIGS. 1 and 2). This means that the whole string of pipe in the wellbore now moves up and down as the wave action (known as heave in the industry) causes the pressure effects of surge (pressure increase as the pipe moves into the hole) and swab (pressure drop as the pipe moves out of the hole). This effect already causes substantial pressure variations in the conventional method of FIG. 3a. 
When the system is closed by the addition of an RCD as shown in FIG. 3d, this effect is even more pronounced by the effect of volume changes by the pipe moving in and out of a fixed volume. As the movement of a pressure wave in a compressed liquid is the speed of sound in that liquid, it implies that the choke system would have to be able to respond at the same or even faster speed. While the electronic sensor and control systems are able to achieve this, the mechanical manipulation of the choke system is very far from these speeds.
Development of RCD's (rotating control devices) originated from land operations where typically the installation was on top of the BOP (blowout preventer). This meant that usually there was no further equipment installed above the RCD. As access was easy, almost all of the current designs have hydraulic connections for lubricating and cooling bearings in the RCD, or for other utilities. These require the external attachment of hoses for operation.
Although some versions have progressed from surface type to being adapted for use on the bottom of the sea (such as described in U.S. Pat. No. 6,470,975), they fail to disclose a complete system for achieving this. Some systems (such as described in U.S. Pat. No. 7,080,685) dispense with hydraulic cooling and lubrication, but require a hydraulic connection to release the assembly.
Furthermore, the range of RCD's and alternatives available means that a custom made unit to house a particular RCD design is typically required (such as described in U.S. Pat. No. 7,080,685). The '685 patent provides only for a partial removal of the RCD assembly, leaving the body on location.
Many ideas have been tried and patents have been filed, but the field application of technology to solve some of the shortcomings in the conventional set-up of FIG. 3a has been limited. All of these modify the existing system in a custom manner, thereby taking away some of the flexibility. There exist needs in the present industry to provide a solution to allow running a pressurized riser for the majority of floating drilling installations to allow closed system drilling techniques, especially managed pressure drilling, to be safely and expediently applied without any major modification to the floating drilling installation.
These needs include, but are not limited to: the capability to pressurize the marine riser to the maximum pressure capacity of its members; the capability to be safely installed using normal operational practices and operated as part of a marine riser without any floating drilling installation modifications as required for surface BOP operations or some subsea ideas; providing full-bore capability like a normal marine riser section when required; providing the ability to use the standard operating procedures when not in pressurized mode; maintaining the weather (wind, current and wave) operating window of the floating drilling installation; providing a means for damping the pressure spikes caused by heave resulting in surge and swab fluctuations; providing a means for eliminating the pressure spikes caused by movement of the rotatable tubulars into and out of a closed system; and providing a means for easily modifying the density of fluid in the riser at any desired point.